Openhole Multistage Completion Evaluation Incorporating Deployment of Downhole Shut-in Tool Application in Sour Carbonate Gas Wells, Field Application

2021 ◽  
Author(s):  
Mauricio Espinosa ◽  
Jairo Leal ◽  
Ron Zbitowsky ◽  
Eduardo Pacheco
Keyword(s):  
Gas Flow ◽  
Operational Risk ◽  
Tool Design ◽  
Lessons Learned ◽  
Differential Pressure ◽  
Gas Wells ◽  
Flow Area ◽  
Gas Well ◽  
Heterogeneous Rocks ◽  
The Impact

Abstract This paper highlights the first successful application of a field deployment of a high-temperature (HT) downhole shut-in tool (DHSIT) in multistage fracturing completions (MSF) producing retrograde gas condensate and from sour carbonate reservoirs. Many gas operators and service providers have made various attempts in the past to evaluate the long-term benefit of MSF completions while deploying DHSIT devices but have achieved only limited success (Ref. 1 and 2). During such deployments, many challenges and difficulties were faced in the attempt to deploy and retrieve those tools as well as to complete sound data interpretation to successfully identify both reservoir, stimulation, and downhole productivity parameters, and especially when having a combination of both heterogeneous rocks having retrograde gas pressure-volume-temperature (PVT) complexities. Therefore, a robust design of a DHSIT was needed to accurately shut-in the well, hold differential pressure, capture downhole pressure transient data, and thereby identify acid fracture design/conductivity, evaluate total KH, reduce wellbore storage effects, properly evaluate transient pressure effects, and then obtain a better understanding of frac geometry, reservoir parameters, and geologic uncertainties. Several aspects were taken into consideration for overcoming those challenges when preparing the DHSIT tool design including but not limited to proper metallurgy selection, enough gas flow area, impact on well drawdown, tool differential pressure, proper elastomer selection, shut-in time programming, internal completion diameter, and battery operation life and temperature. This paper is based on the first successful deployment and retrieval of the DHSIT in a 4-½" MSF sour carbonate gas well. The trial proved that all design considerations were important and took into consideration all well parameters. This project confirmed that DHSIT devices can successfully withstand the challenges of operating in sour carbonate MSF gas wells as well as minimize operational risk. This successful trial demonstrates the value of utilizing the DHSIT, and confirms more tangible values for wellbore conductivity post stimulation. All this was achieved by the proper metallurgy selection, maximizing gas flow area, minimizing the impact on well drawdown, and reducing well shut-in time and deferred gas production. Proper battery selection and elastomer design also enabled the tool to be operated at temperatures as high as 350 °F. The case study includes the detailed analysis of deployment and retrieval lessons learned, and includes equalization procedures, which added to the complexity of the operation. The paper captures all engineering concepts, tool design, setting packer mechanism, deployment procedures, and tool equalization and retrieval along with data evaluation and interpretation. In addition to lessons learned based on the field trial, various recommendations will be presented to minimize operational risk, optimize shut-in time and maximize data quality and interpretation. Utilizing the lessons learned and the developed procedures presented in this paper will allow for the expansion of this technology to different gas well types and formations as well as standardize use to proper evaluate the value of future MSF completions and stimulation designs.

Researches of technological mode of operation of gas wells with a single-lift elevator at a critical speed of upper flow

2021 ◽  
pp. 97-103
Author(s):  
R.A. Gasumov ◽  
◽  
E.R. Gasumov ◽  
Keyword(s):  
Gas Flow ◽  
Operating Conditions ◽  
Physical Parameters ◽  
Gas Wells ◽  
Gas Well ◽  
Field Development ◽  
Mode Of Operation ◽  
Water Drops ◽  
Liquid Flows ◽  
Technological Mode

The article discusses the modes of movement of gas-liquid flows in relation to the operating conditions of waterlogged gas wells at a late stage of field development. Algorithms have been developed for calculating gas well operation modes based on experimental work under conditions that reproduce the actual operating conditions of flooded wells of Cenomanian gas deposits. The concept of calculating the technological mode of operation of gas wells with a single-row elevator according to the critical velocity of the upward flow is considered based on the study of the equilibrium conditions of two oppositely directed forces: the gravity of water drops directed downward and the lifting force moving water drops with a gas flow directed upward. A calculation was made according to the method of the averaged physical parameters of formation water and natural gas in the conditions of flooded Cenomanian gas wells in Western Siberia. The results of a study of the dependence of the critical flow rate of Cenomanian wells on bottomhole pressure and diameter of elevator pipes are presented.

The Use of an r-z Model To Study the Effect of Completion Technique on Gas Well Deliverability

1973 ◽  
Vol 13 (05) ◽  
pp. 259-266
Author(s):  
Henry B. Crichlow ◽  
Paul J. Root
Keyword(s):  
Gas Flow ◽  
Flow Equation ◽  
Coefficient Of Performance ◽  
Gas Wells ◽  
Gas Well ◽  
Real Gas ◽  
The Real ◽  
Fluid Properties ◽  
Set Up ◽  
Gas Potential

Abstract A digital computer model of a radial gas reservoir was constructed to investigate the effect of completion techniques on gas well deliverability. The model was a standard r-z model divided linearly in the z-direction and logarithmically in the r-direction. Individual reservoir properties were assigned to each element of the model grid. These include porosity, radial and vertical permeability, and water saturation. A finite-difference approach was used to set up the flow equations, and both alternating direction implicit procedure (ADIP) and line successive overrelaxation (LSOR) were used to set up the system of simultaneous equations. The Thomas algorithm was used to solve the tridiagonal systems. From this research the following conclusions were drawn:(1)The real gas potential is effective in linearizing the gas flow equation. For nonturbulent flow the coefficient of performance in the backpressure equation, Q = C [ (Pe) - (Pw)]n can be evaluated independently oil the fluid properties of the gas.(2)Partially producing properties of the gas.(2)Partially producing intervals constitute a skin, the magnitude of which depends on the location of the perforations and the anisotropic nature of the medium.(3)In a damaged or stimulated well, within limits, the significant factor in deliverability reduction is the kind rather than the extent of the damage.(4)From the numerical standpoint ADIP is a more efficient method in "well-behaved" problemsthat is, in homogeneous systemswhereas LSOR is better suited to partially open and nonhomogeneous systems. Introduction Calculation of the flow rate and prediction of the deliverability of gas wells are factors of great economic importance to the natural gas industry. Consequently, the accurate analysis of gas flow in producing gas wells has been a subject of considerable interest, and many papers dealing with it may be found in the literature. One of the earliest methods for calculating gas flow, that of Jenkins and Aronofsky, involved the succession of steady states. Janicek and Katz, using a similar assumption that the rate of pressure change with time is independent of the radius at any given time, derived a set of relatively straightforward predictive equations. Other calculational methods are based on solutions to the partial differential equation describing gas flow in a porous medium. Until recently the analysis was based on linearizations that required evaluation of the gas properties at some average pressure. As a result, these solutions can be applied only when the flow gradients are small. Today gas reservoirs are being discovered at much greater depths and at relatively higher pressures. In many cases the formation permeability pressures. In many cases the formation permeability to gas is quite low. Thus, solutions to be linearized equation can lead to serious errors in predicting deliverability (and, hence, reserves) predicting deliverability (and, hence, reserves) because of the large drawdowns occurring in these systems. The simplifying assumptions implied by the linearized equations are not necessary when the real gas potential proposed by Al-Hussainy et al. is used. This function greatly facilitates the incorporation of the pressure-dependent variables, viscosity, and gas deviation factor into a mathematical model of gas flow. Its use reduces the unsteady-state flow equation directly to a form analogous to that of the diffusivity equation without the tacit assumptions that the pressure gradients within the flow system are small. Furthermore, the coefficients of the spatial derivatives no longer contain the pressure-dependent fluid properties. Because of these advantages the (p) function was used in this investigation of gas well deliverability. SPEJ P. 259

New Techniques Developed to Safely Unload and Test High Rate Offshore Sour Gas Well With 7-in Monobore Completions-Lessons Learned Gas Wells Offshore Sarawak Malaysia

2018 ◽  
Author(s):  
Azraii Fikrie Azraii ◽  
Adhi Naharindra Adhi ◽  
Thian Hui Chie Hui Chie ◽  
Claire Chang Claire ◽  
Ridzuan Shaedin Ridzuan ◽  
...  
Keyword(s):  
Lessons Learned ◽  
High Rate ◽  
Gas Wells ◽  
New Techniques ◽  
Gas Well ◽  
Sour Gas

scholarly journals A productivity prediction method for condensate gas reservoir

2020 ◽  
Vol 213 ◽  
pp. 02001
Author(s):  
Quan Hua Huang ◽  
Hong Jun Ding ◽  
Xing Yu Lin
Keyword(s):  
Pressure Gradient ◽  
Stress Sensitivity ◽  
Water Production ◽  
Gas Wells ◽  
Gas Reservoir ◽  
Gas Well ◽  
Well Productivity ◽  
Inclined Angle ◽  
The Impact ◽  
Starting Pressure Gradient

At present, multiphase flow productivity calculation requires many parameters, and most of them only consider oil and gas two-phase flow, which is complicated and limited. Therefore, a reasonable productivity formula of condensate gas reservoir with producing water is needed. The three-zone model of condensate gas reservoirs is generally applied to the physical model for inferring productivity. On this basis, an improved model is established, which includes that different seepage characteristics are considered for different zones. Moreover, the effects of inclined angle and water production on gas wells are regarded as pseudo-skin factors and additional-skin factors. In addition, Zone I considers the effects of high-speed nonDarcy effect(HSND), starting pressure gradient, stress sensitivity, inclined angle and water production; Zone II is the same way excepting starting pressure gradient and stress sensitivity ; Zone III only considers the effects of inclined angle and water production. As a result, a productivity equation with multiple factors for condensate gas wells is established. Through analysing cases and influences in H gas reservoir X1 well, the HSND, starting pressure gradient, stress sensitivity and water production have a negative impact on gas well productivity, but the inclined angle is opposite. Founded that the starting pressure gradient impacts on productivity is less than the HSND because of the limited radius of Zone I; the impact of the HSND on productivity increases with the decreasing of bottom hole pressure; the impact of water production on gas well productivity is much higher. When the angle is over 60°, the effect of gas

Analysis of Erosion and Failure in the Sudden Expansion Fracturing Tubing of Deep Gas Wells

2010 ◽  
Author(s):  
Yan Xu ◽  
Zunce Wang ◽  
Sen Li ◽  
Fengxia Lv ◽  
Yuejuan Yan ◽  
...  
Keyword(s):  
Impact Angle ◽  
High Rate ◽  
Sudden Expansion ◽  
Gas Wells ◽  
Gas Well ◽  
Erosion Models ◽  
Fluid Theory ◽  
Simulation Results ◽  
The Impact ◽  
Two Fluid

With the increasing of flow rate during fracturing in deep gas well, the erosion of fracturing tubing is an issue of immense concern to the industry. Based on the Euler-Euler two–fluid theory, the numerical simulations have been performed to predict the flow field in the sudden expansion fracturing tubing. The velocity distributions and sand concentration profiles are obtained, and the simulation results show that separation and reflux come into being in the sudden expansion fracturing tubing when pumping sand slurries at high rate, and the sand concentration increases at some regions. The erosion and failure of the fracturing tubing are relevant to the sand concentration, the velocity and the impact angle. The erosion model was established with the erosion experiment, and the numerical simulation results were used to describe the erosion rate of sudden expansion fracturing tubing according to the established erosion models. The mainly erosion region obtained through the simulation is basically agree with the failure region of tubing during fracturing in deep gas wells.

Vibration Characteristics Analysis of Tubing String in Three-High Gas Well

2012 ◽  
Vol 455-456 ◽  
pp. 395-399 ◽  
Author(s):  
Min Yang ◽  
Yu Ma ◽  
Shi Gui Li
Keyword(s):  
Structural Characteristics ◽  
Mass Matrix ◽  
Fluid Pressure ◽  
Vibration Characteristics ◽  
Efficient Production ◽  
Superposition Method ◽  
Gas Wells ◽  
Gas Well ◽  
Tubing String ◽  
The Impact

Three-high gas well is High-production gas well, High-temperature gas well and High-sulfur gas well.In the mining process of three-high gas wells, due to the impact of the role of the fluid and the tubing string fluctuations lead to severe vibration, the role could easily lead to severe vibration column damage. Based on the high gas flow during the mining shaft and column structural characteristics, taking into account the weight of the tubing string, the packer constraints impact characteristics of steel tubing, pre-stressing, the fluid pressure force on the tubing string's vibration characteristics. Established a tubing string vibration equation, and the establishment of the corresponding mass matrix obtained, the stiffness matrix and damping matrix. Lanczos algorithm with inherent characteristics of the pipeline parameters. The modal superposition method to analyze vibration characteristics of the tubing string, to ensure that the calculation speed in the case met the approximate solution of engineering precision, For the three-high gas wells safe, efficient production of effective technical support.

The First Behind-Casing Fiber-Optic Installation in a High-Pressure High-Temperature Deep Gas Well in Oman

2022 ◽  
Author(s):  
Sultan Salim Al Shoaibi ◽  
Juan Chavez Florez ◽  
Shaima Al Farsi ◽  
Adnan Al Hinai ◽  
Alvaro Nunez ◽  
...  
Keyword(s):  
High Pressure ◽  
High Temperature ◽  
Fiber Optic ◽  
Production Performance ◽  
Distributed Temperature Sensing ◽  
Gas Wells ◽  
Fiber Optic Cable ◽  
Gas Well ◽  
High Pressure High Temperature ◽  
The Impact

Abstract This paper discusses the first fiber-optic (FO) installation in a vertical high-pressure high-temperature deep gas well in PDO, Oman. A specially designed fiber-optic cable was successfully installed and cemented behind the production casing, which was subsequently perforated in an oriented manner without damaging the cable. This paper also describes how the fiber-optic cable was used afterwards to acquire Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS) data for the purpose of hydraulic fracturing diagnostics. Fiber-optic surveillance is becoming an increasingly important activity for well and reservoir surveillance. The added complexity of the fiber-optic installation will affect the well design, which is one of the elements that requires focused attention, especially when the fiber is installed behind casing. The impact on casing design, wellhead design, perforation strategy, and logging requirements will all be discussed. In order for a well to be completed with a permanent fiber-optic cable, a few critical procedures need to be followed, including: –modifying the wellhead design to include feedthrough ports for the cable;–optimizing the cement design;–imposing strict procedures to ensure the cable is installed behind the casing without getting stuck;–changing the perforation phasing to avoid damaging the cable;–mapping the location of the cable to allow the gun string to be oriented away from the cable. The fiber-optic cable itself needed to be designed to be protected in such a way that it would not be damaged during installation and completion (perf/frac) activities. Furthermore, the cable was also optimized to improve its detectability, to aid the oriented perforation. In deep gas wells, much more than in conventional shallow water injectors or oil producers, the well integrity aspect should be given special attention. Specifically, any risks related to unwanted gas leaks, either through the control line, poor cement, or because of other design errors should be avoided. In deep gas wells, high temperature and pressure will also play a big role in the expected lifespan of the cable. Finally, the well was hydraulically fractured in four stages, using the "plug-and-perf" technique, during which DAS and DTS data were acquired continuously and across all depths of the well. The data provided valuable information on the effectiveness of each of the frac stages, it could be used to analyze screen-outs and detect out-of-zone injection, and recommendations for the optimizations of future hydraulic frac designs could be derived. The fiber-optic data were also integrated with other open-hole data for improved understanding of the reservoir performance. The next step will be to acquire repeated time-lapse DAS and DTS data for production profiling, to gain more insights of how the long-term production performance is affected by the hydraulic frac operations.

Lessons Learned: How to Produce More Hydrocarbons from Blowout Wells

2016 ◽  
Author(s):  
Xueqing Tang ◽  
Lirong Dou ◽  
Ruifeng Wang
Keyword(s):  
Gas Production ◽  
Lessons Learned ◽  
Oil Well ◽  
Fractured Reservoir ◽  
Naturally Fractured Reservoir ◽  
Gas Well ◽  
Hydrocarbon Recovery ◽  
Water Breakthrough ◽  
Naturally Fractured ◽  
The Impact

ABSTRACT Deep formation damage caused by killing fluid frequently occurs in blowout wells and clean-up operations may result in early water breakthrough and less hydrocarbon recovery. This paper presents three innovative practices applied in oil and gas wells that suffered blowout accidents for more hydrocarbon recovery. i.e.: For a blowout oil well, N2 huff and puff process can be applied for clean-up around the wellbore. During the first several cycles, the well got clean-up and output and wellhead pressure increased.For a blowout gas well in a massive gas pool, controllable drawdown pressure is recommended due to its updip location. The drawdown pressure should be met for both clean-up and minimum water coning. When water breakthrough appears, then neighboring wells at lower locations produce at larger drawdown pressure than that of blown-out well to minimize the impact of water influx on production of blowout well.For a blowout gas well in a faulted, naturally fractured reservoir, drawdown pressure should be maintained at the level of no liquid-loading in the wellbore. Gas and water co-production should be kept stable. Any shut-in of the well must be avoided. These methods have been successfully utilized in more than 40 wells for over 50 years. The three typical field examples are illustrated. One of them is an oil well in sandstone reservoir, with double oil rate as the nearby wells. The rest are a gas well in massive carbonate pool with bottom water, with the most prolific gas production in the field, and a gas well in a naturally fractured reservoir, with Gp of over 180 BCF.

Characteristics of Physician Relocation Following Hurricane Katrina

2009 ◽  
Vol 95 (1) ◽  
pp. 6-12
Author(s):  
Kusuma Madamala ◽  
Claudia R. Campbell ◽  
Edbert B. Hsu ◽  
Yu-Hsiang Hsieh ◽  
James James
Keyword(s):  
Hurricane Katrina ◽  
Gulf Coast ◽  
General Medicine ◽  
The United States ◽  
Lessons Learned ◽  
Bivariate Analysis ◽  
Fisher Exact Test ◽  
Exact Test ◽  
Factors Associated ◽  
The Impact

ABSTRACT Introduction: On Aug. 29, 2005, Hurricane Katrina made landfall along the Gulf Coast of the United States, resulting in the evacuation of more than 1.5 million people, including nearly 6000 physicians. This article examines the relocation patterns of physicians following the storm, determines the impact that the disaster had on their lives and practices, and identifies lessons learned. Methods: An Internet-based survey was conducted among licensed physicians reporting addresses within Federal Emergency Management Agency-designated disaster zones in Louisiana and Mississippi. Descriptive data analysis was used to describe respondent characteristics. Multivariate logistic regression was performed to identify the factors associated with physician nonreturn to original practice. For those remaining relocated out of state, bivariate analysis with x2 or Fisher exact test was used to determine factors associated with plans to return to original practice. Results: A total of 312 eligible responses were collected. Among disaster zone respondents, 85.6 percent lived in Louisiana and 14.4 percent resided in Mississippi before the hurricane struck. By spring 2006, 75.6 percent (n = 236) of the respondents had returned to their original homes, whereas 24.4 percent (n = 76) remained displaced. Factors associated with nonreturn to original employment included family or general medicine practice (OR 0.42, 95 percent CI 0.17–1.04; P = .059) and severe or complete damage to the workplace (OR 0.24, 95 percent CI 0.13–0.42; P < .001). Conclusions: A sizeable proportion of physicians remain displaced after Hurricane Katrina, along with a lasting decrease in the number of physicians serving in the areas affected by the disaster. Programs designed to address identified physician needs in the aftermath of the storm may give confidence to displaced physicians to return.

Optimizing electronic capture of patient-reported outcome measures in oncology clinical trials: lessons learned from a qualitative study

2020 ◽  
Vol 9 (17) ◽  
pp. 1195-1204
Author(s):  
Florence D Mowlem ◽  
Brad Sanderson ◽  
Jill V Platko ◽  
Bill Byrom
Keyword(s):  
Patient Reported Outcome Measures ◽  
Patient Reported Outcome ◽  
Lessons Learned ◽  
Structured Interviews ◽  
Patient Reported ◽  
Oncology Clinical Trials ◽  
Anticancer Treatment ◽  
Fit For Purpose ◽  
The Impact ◽  
Electronic Implementation

Aim: To understand the impact of anticancer treatment on oncology patients’ ability to use electronic solutions for completing patient-reported outcomes (ePRO). Materials & methods: Semi-structured interviews were conducted with seven individuals who had experienced a cancer diagnosis and treatment. Results: Participants reported that the following would impact the ability to interact with an ePRO solution: peripheral neuropathy of the hands (4/7), fatigue and/or concentration and memory issues (6/7), where they are in a treatment cycle (5/7). Approaches to improve usability included: larger, well-spaced buttons to deal with finger numbness, the ability to pause a survey and complete at a later point and presenting the recall period with every question to reduce reliance on memory. Conclusion: Symptoms associated with cancers and anticancer treatments can impact the use of technologies. The recommendations for optimizing the electronic implementation of patient-reported outcome instruments in this population provides the potential to improve data quality in oncology trials and places patient needs at the forefront to ensure ‘fit-for-purpose’ solutions.

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